1. Field of the Invention
The present invention relates to fluid systems in the oil and gas industry, in particular, a fracturing fluid system. In particular, the present invention relates to a fracturing fluid system with ascorbic acid for high temperatures. More particularly, the present invention relates to a fracturing fluid system with ascorbic acid for stable viscosity at temperatures between 150-260 degrees Celsius.
2. Description of Related Art Including Information Disclosed Under 37 CFR 1.97 and 37 CFR 1.98.
Fluid systems transport materials and chemicals and perform work, such as powering downhole tools with hydraulics, during drilling and production operations for oil and gas. Drilling mud is the lubricant and transport material during drilling. The drilling mud fluid is pumped from the surface to the wellbore with coolants and stabilizers to provide relief to the mechanical tools in the extremely hot and pressurized environmental conditions at the drill bit. The pulverized rock at the drill bit is suspended in the drilling mud and pumped back out of the borehole for removal. Fracturing fluid systems are the fluids pumped into the wellbore with a proppant in order to fracture a rock formation. A high pressure injection of fracturing fluid system at a target depth creates cracks in rock formation, and the fracturing fluid system enters these cracks. The proppant, such as sand or other particulates, prevent the cracks from closing when the pressured injection of fluid stops. The fracture is held open by the proppant so that the formation remains permeable by oil, gas, salt water, and other fluids, which can now be pumped through the well.
Fracturing fluid systems are comprised of water, proppant, and additives. The additives control rheological properties of the fracturing fluid system so as to allow the transport of proppant for different formations under various conditions. High viscosity fracturing relies on gelling agents, such as guar gum, to increase viscosity and suspend the proppant for delivery as far as possible into the cracks of the fracture. High rate or high velocity relies on low friction and fast pumping fracturing fluid systems to reach deeper into a rock formation. Additives can be principally chosen for a desired ability to suspend proppant or to be pumped at a particular velocity.
Additives can also be selected for recovery of the fracturing fluid system. Once the proppant is delivered, the fluid components of the fracturing fluid system must be removed. Additional water can be pumped to flush the fracture. During the fluid injection, additives can be released into the fracturing fluid system to alter the gelling agent, so as to reduce viscosity and more easily release the proppant from suspension. The fracturing fluid system waste contains the water and additives, which can contaminate the environment. With so much water being used, the amount of produced wastewater with additives is also great. There is a risk to ground water, when fracturing fluid system is injected and recovered, and there is a risk to surface water, when produced wastewater is stored in waste pits and retention ponds. Additives can be chosen to be more biologically friendly in order to lessen environmental impact.
Fracturing fluid systems fail, when the proppant is not delivered or not anchored in the fracture. The viscosity may be too high or the velocity is too slow, so that the proppant cannot reach deep enough into the cracks in the formation. The viscosity may be too low or the velocity too fast, so that the proppant is not suspending in the fluid component long enough to reach deep into cracks. Also, when the fluid component washes out of the fracture, the proppant must remain in the fracture, separate from the liquid components of the fracturing fluid system. If the fracturing fluid system remains too viscous, the washing out may dislodge and carry proppant back out of the fracture.
With advances in the drilling to greater depths, the high temperature conditions at the greater depths cause conventional fracturing fluid systems to fail. Fracturing fluid systems with gelling agents lose stability and cannot hold viscosity to suspend the proppant into the formation. The prior art discloses fracturing fluid systems with selected additives to account for these high temperature conditions.
U.S. Pat. No. 8,022,015, issued to Paul S. Carman et al. on 20 Sep. 2011, discloses a method of fracturing with a phenothiazine stabilizer. Well treatment fluids and methods of treating high temperature subterranean formations of up to about 260 degrees C. are disclosed. The additives of the fracturing fluid include a gelling agent, a high molecular weight synthetic copolymer, a phenothiazine stabilizer, and a pH adjusting agent that maintains a pH in a range of about 4.5 to about 5.25 for the fluids. The phenothiazine stabilizer is an electron donating compound, which maintains viscosity of the gel by slowing hydrolysis of the fracturing fluid system at temperatures above 148.9 degrees C. The method also requires a suitable crosslinking agent for the getting agent and a high molecular weight synthetic polymer to maintain viscosity at the high temperatures.
U.S. Pat. No. 8,691,734, issued to Paul S. Carman et al. on 8 Apr. 2014, also discloses a method of fracturing with a phenothiazine stabilizer. Foaming affects the amount of water and viscosity of the fracturing fluid system. This method includes a foaming agent, instead of a gelling agent, as an additive to reduce the amount of water required for the fracturing fluid system.
Phenothiazine is a known insecticide and treatment for worms in livestock and humans. Derivatives of phenothiazine have been used in antipsychotic drugs. Phenothiazine is not biologically friendly, and there is an elevated risk to the environment with potential insecticides contaminating ground water. Furthermore, phenothiazine is not soluble in water, but the fracturing fluid system is more than 90% water. More solvents are required to dissolve phenothiazine in the fracturing fluid system. The use of a foaming agent, instead of a gelling agent, further reduces the amount of water, but more solvents are still needed to accommodate these high temperature fracturing fluid systems.
Advancement in drilling technology has not always permitted oil and gas production at certain depths with extreme environmental conditions of temperature and pressure. The prior art discloses other additives for fracturing fluid systems, although these prior art references do not address high temperature conditions. Other additives to regulate stability of the fracturing fluid system under more conventional conditions include various cross linking agents and stabilizers. Ascorbic acid is one such known additive.
The inherent properties of ascorbic acid, as an acid and as a stabilizer, are known in the prior art. Ascorbic acid is a known additive in drilling fluids because of these inherent properties. For example, United States Publication No. 20150175877, published for Shindgikar et al. on 25 Jun. 2015, discloses ascorbic acid as a chelating agent to bind metal ions in a fracturing fluid system. U.S. Pat. No. 4,752,404, issued to Burns et al. on 21 Jun. 1988, teaches blends of water soluble polymers with ascorbic acid as a stabilizer or sequestering agent. U.S. Pat. No. 7,833,949, issued to Li et al. on 16 Nov. 2010, describes another fracturing fluid system with a polysaccharide having ascorbic acid mentioned as a possible reducing agent. U.S. Pat. No. 7,678,745, issued to Parris et al. on 16 Mar. 2010, discloses a fracturing fluid system with an organic peroxide, including a side note mentioning ascorbic acid as a stabilizer.
It is an object of the present invention to provide a method for well stimulation by hydraulic fracturing a rock formation through a wellbore under high temperature conditions.
It is another object of the present invention to provide a method for hydraulic fracturing a rock formation at a temperature range of 150-260 degrees Celsius.
It is an object of the present invention to provide a method for well stimulation by hydraulic fracturing, wherein the fracturing fluid system has ascorbic acid as a stabilizer.
It is another object of the present invention to provide a method for well stimulation by hydraulic fracturing with a gel based fracturing fluid system having viscosity stabilized by ascorbic acid.
It is an object of the present invention to provide a method for well stimulation by hydraulic fracturing with a fracturing fluid system having a high molecular weight synthetic polymer as the gelling agent.
It is an object of the present invention to provide a method for well stimulation by hydraulic fracturing, wherein the fracturing fluid system has ascorbic acid as a stabilizer and a pH adjusting agent.
It is another object of the present invention to provide a method for well stimulation by hydraulic fracturing, wherein the fracturing fluid system with delayed cross-linking has ascorbic acid as a stabilizer, and a pH adjusting agent.
It is still another object of the present invention to provide a method for well stimulation by hydraulic fracturing, wherein the fracturing fluid system has ascorbic acid as a stabilizer and a pH adjusting agent, and another pH adjusting agent adjusted according to the amount of ascorbic acid and other additives.
It is an object of the present invention to provide a method for well stimulation by hydraulic fracturing under high temperature conditions by injecting a stable fracturing fluid system having a biologically friendly stabilizer.
It is another object of the present invention to provide a method for well stimulation by hydraulic fracturing under high temperature conditions by injecting a stable well treatment fluid having a stabilizer with less risk of environmental contamination.
These and other objectives and advantages of the present invention will become apparent from a reading of the attached specification.